The invention relates to method and system for internally lining a tubing string to protect the tubing string against corrosion and/or leakage.
Wellbores for the exploration and production of oil, gas or other minerals from subterranean reservoir layers are typically provided with protective tubing, casing and/or other liner strings. These may include a pipe string lowered into an openhole section of the wellbore and cemented in place. Herein, the term casing is typically used to indicate a pipe string extending from surface into the wellbore, whereas liner may typically be used to indicate a pipe string which extends from a downhole location further down the wellbore. Hereinafter, the term casing will be primarily used, but the invention is equally applicable to liner.
The casing or liner strings may be designed to withstand a variety of forces, such as collapse, burst, and tensile failure, as well as chemically aggressive brines. The casing string is typically assembled from multiple interconnected pipe sections, having a length of for instance about 10 meters each. Casing connections connect adjacent pipe sections. The casing sections may be fabricated with male threads on each end, wherein shorter-length casing couplings with female threads are used to join the individual sections of casing together. Alternatively, pipe sections may be fabricated with male threads on one end and female threads on the other.
Casing may be run to protect fresh water formations, isolate a zone of lost returns or isolate formation layers with significantly different pressure gradients. The operation during which the casing is put into the wellbore is commonly called “running pipe.”
Inside the innermost casing, a wellbore may typically be provided with another tubing string, typically referred to as production string or production tubing. Herein, the production tubing may be assembled with other completion components to make up the production string. The production string is the primary conduit through which reservoir fluids are produced to surface. The production string is typically assembled with tubing and completion components in a configuration that suits the wellbore conditions and the production method. The tubing itself may be made up from interconnected pipe sections, in a similar fashion to the casing strings. An important function of the production string is to protect the primary wellbore tubulars, including the casing and liner, from corrosion or erosion by the reservoir fluid.
Interior surfaces of the production tubing and their associated connections are frequently subjected to one or more of relatively high temperatures, high pressures and highly corrosive fluids. Temperatures may range up to 175° C. or more. Pressures may be as high as 1400 bars or more. The reservoir fluids may be highly corrosive, for instance due to the combination of hydrocarbons, CO2 and/or H2S in the presence of water. The use of secondary and tertiary enhanced recovery methods in hydrocarbon production, such as gas injection, water flooding and chemical flooding, may further aggravate the situation.
Pipe sections for wellbore tubulars, including the casing or production tubular, are usually manufactured from plain carbon steel with varying compositions that is heat-treated to varying strengths. Alternatively, pipe sections may be specially fabricated of stainless steel, nickel alloys, aluminium, titanium, fiberglass and other materials.
Materials have different resistance to corrosion. Carbon steel for instance is relatively inexpensive, but also more prone to corrosion than the other materials listed above.
Several types of corrosion mechanisms exist, including: erosion-corrosion (also known as impingement), stress corrosion cracking, sulphide stress cracking, pitting, and galvanic corrosion.
Corrosion in metals may be caused by the flow of electricity from one metal to another metal or from one part of the surface of one piece of metal to another part of the same metal where conditions permit the flow of electricity. Further, a moist conductor or electrolyte must be present for this flow of energy to take place. Energy passes from a negative region to a positive region via the electrolyte media.
Electrical contact or coupling of dissimilar metals frequently causes increased corrosion. This form of corrosion is generally referred to as galvanic corrosion. Galvanic corrosion is quite prevalent and troublesome, occurring in a wide variety of circumstances. For example, coupling aluminium and iron pipe together will result in very rapid corrosion of the aluminium pipe section. The galvanic corrosion mechanism may be illustrated by considering the effect of electrically connecting zinc to platinum immersed in sea water. Under these conditions, the platinum is inert and does not corrode, while the zinc is attacked. The reactions occurring on the surface of the zinc are the anodic oxidation of zinc to zinc ions, and the cathodic reduction of dissolved oxygen to hydroxide ions. If the electrical potentials of these two metals are measured, the platinum would be found to have a positive potential, while the zinc would be found to have a negative potential. As may be appreciated, as the potential difference increases, galvanic corrosion increases.
Obviously, from a corrosion standpoint, the replacement of steel tubulars and associated hardware with materials less subject to corrosion would be highly desirable in gas and oil applications, if it were practical or economically viable. Non-metallic components, such as fiberglass casing, tubing, sucker rods and the like are finding their way into oil field applications. Performance limitations, including service loads, pressures and temperatures, restrict the across-the-board replacement of metallic hardware, however. On the other hand, pipe sections made of solid corrosion resistant alloy (CRA), such as stainless steel and nickel alloy, may provide sufficient corrosion resistance. But tubular sections made of solid corrosion resistant alloys are typically much more expensive than carbon steel. The latter may render projects uneconomical. In addition, newly developed hydrocarbon reservoirs are producing increasingly corrosive hydrocarbons, for instance including a greater percentage of H2S, requiring higher grade Corrosion Resistant Alloys (CRAs). And higher grade CRAs are increasingly more expensive. For instance, compared to API grade P110 carbon steel, the same pipe section made of CRA may be up to 5, 10 or even 25 times more expensive (when made of 316L, SM25CRW-110/125, or C22 CRA respectively).
Several manufacturing methods have been developed for producing corrosion resistant clad or lined carbon steel tubular, for instance for transporting oil and gas, to achieve economic advantages over solid corrosion resistant alloy (CRA) tubular such as stainless steel and nickel alloy. However, the use of these clad or lined tubulars has not gained acceptance for downhole tubular primarily due to the lack of a thread connection that has demonstrated adequate corrosion resistance performance.
To guard against galvanic corrosion, insulating coatings may be applied. In order for a coating to be used on tubular sections and threaded couplings to protect the metal substrate from corrosion, the coating must be resistant to attack and maintain its adherence to the metal substrate under the harsh downhole conditions referred to above.
In various oil and gas applications, steel pipe is provided with a lining of corrosion-resistant material. For example, it is known to bond various epoxy-based coatings to the interior of the pipe, as well as coatings containing polyethylene, polyvinyl chloride and other thermoplastic and thermosetting materials.
Of the various polymeric coating materials, arylene sulfide polymers have gained wide acceptance, see for instance U.S. Pat. No. 3,354,129. Generally, these polymers consist of a recurring aromatic structure coupled in repeating units through a sulfur atom. Commercially available arylene sulfide polymers which have been used for coating oil and gas pipes and pipe couplings are polyphenylene sulfides. The polyphenylene sulfides used in oil and gas applications exhibit high melting points, outstanding chemical resistance, thermal stability and are non-flammable. They are also characterized by high stiffness and good retention of mechanical properties at elevated temperatures as well as the ability to deform smoothly, thereby, for example, preventing the galling of threads, even at high thicknesses.
U.S. Pat. No. 3,744,530 describes polyphenylene sulfide coated pipes, wherein the polyphenylene sulfide coating also contains a filler, such as iron oxide, in an amount of between 5% to 30%.
While polymeric coated pipes and couplings have gained wide acceptance in applications requiring corrosion protection, the cracking of such coatings during installation and in use tends to limit their insulating effect, increasing the likelihood that galvanic corrosion will take place. This is particularly relevant in the female part or pin-end of the connections, where cracking may occur during assembly of the connection. Moreover, the polymeric coatings of threaded couplings are particularly prone to cracking due to the stresses imparted during assembly of connections. In addition to cracking, many polymers allow diffusion of hydrogen and other light hydrocarbons through the thickness of the coating or liner, thereby allowing gas to accumulate between layers, which, in the case of a corrosion resistant liner could result in collapse if the pressures in the bore and annulus become unbalanced.
JP 60 109686 A (KAWASAKI HEAVY IND LTD) 15 Jun. 1985 provides a pipe system for transport of corrosive fluids. The pipe system comprises a tubular member made of a corrosion prone metal. Each tubular member is provided with an inner lining of a corrosion resistant material. At each end, the tubular member and the inner lining are connected to a threaded coupling member, which is made of a corrosion resistant material. The tubular member and the liner are connected to the threaded coupling member by a weld seam. But the welding of solid CRA couplings to a carbon steel pipe body, or the welding related method, can cause issues in itself. See for instance the description of galvanic corrosion above. In addition, the cost saving from using clad steel rather than solid CRA is particularly valid when the total wall thickness of the pipe increases. When the product of outer diameter (OD) times wall thickness (T) decreases however, the cost benefit of corrosion resistant alloy clad pipe versus solid CRA pipe decreases rapidly. For instance for pipe clad with Incoloy 825, the cost benefit is reduced to nil for tubulars having smaller OD×T. The latter however are typically used for production tubing.
While the use of corrosion resistant alloys for corrosion control has demonstrated superior corrosion resistance properties, they are quite costly and exhibit complex manufacturing and handling constraints. The price of high-performance steel, such as 18-8 stainless steel, may be about 5 times as expensive as carbon steel. Nickel alloys for instance, which may also include high percentages of chromium (e.g. more than 10%) and/or molybdenum, may exceed the price of carbon steel with a factor of about 20 to 30. Nickel alloys, however, are often the material of choice in environments containing relatively large volumes of H2S. For instance when the H2S partial pressure exceeds 5 to 10 bars, nickel alloys may be required.
In oilfield applications, polymeric coatings will be unsuitable when the partial pressures of either CO2, H2S and/or water exceed a certain threshold, as these materials may permeate through the polymeric coating, which may lead to corrosion of the carbon steel base material. Also, the temperature range wherein polymeric coatings can be applied is typically limited to a maximum of about 100 to 150 degree C.
US-2007/0095532 discloses an apparatus to deploy a patch comprising an inner metal tube and an outer resilient sealing member. Suitably, the inner metal tube is formed from steel, preferably, carbon steel. The outer resilient sealing member is formed from an elastomeric material. Suitably, the patch may be from 10 to 1000 feet in length.
As a disadvantage, in the disclosure of US-2007/0095532, the length of the liner patch is inherently limited by the apparatus described. The liner patch is clamped by extending and retracting slips attached to the apparatus, so the weight of the liner patch is carried by the friction these slips exert on the liner. The force applied by these slips determines the frictional force. The extending and retracting slips will have insufficient capacity to support liner exceeding a certain length, such as several kilometres. Furthermore, in the case of a very thin liner, the pressure that the slips can exert before deforming the liner is minimal, minimizing the friction force also. Although a thin liner is lighter than a thicker patch, the weight of the liner is still typically in the order of 1.3 kg/m. This would provide a total weight of several thousand kilograms if one would consider lining the production tubing along the length of the wellbore.
As hydrocarbon wellbores extend to ever greater target depths, for instance in the range of five to ten kilometres or even more, the apparatus of US-2007/0095532 would be unsuitable to provide a liner patch to the entire inner surface of the production tubing.
Furthermore, the apparatus of US-2007/0095532 is supported by a wireline which, in the configuration as disclosed, would have to travel through the liner. For longer lengths, the practicalities of threading several kilometres of wireline through the liner patch, while still supporting the weight of the liner by the wire line while running into the well, are unrealistic. This is supported by the exemplary length of liner patch as disclosed in US-2007/0095532, which is limited to 1000 feet (about 300 meters).
US-2010/0247794-A1 wellbore tubing lining method wherein a polymer layer is cured downhole actinic radiation. The liner is introduced in the borehole via an apparatus attached to a wireline, which would than expand the liner via a vessel or bladder on a wire line. The bladder will inflate along the full length of the liner to expand the liner. The system is limited to the delivering of a polymer liner. Also, the system can only be applied for limited lengths. The fabrication of a bladder or vessel to expand the liner will inherently limit the length of the liner to be expanded. Providing a bladder which extends along the entire length of the production tubing will be impossible. Moreover, the necessity to run such a vessel into the hole will further limit the maximum length thereof.
U.S. Pat. No. 3,785,193 discloses a liner expanding apparatus and a method including lowering and affixing a liner by means of wireline. The liner is crimped onto an expansion tool, and hangs down from it. This configuration has similar limitations to patent documents US-2007/0095532 and US-2010/0247794-A1 described above, in that the clamping of the liner is based on friction. The friction is insufficient for longer lengths of liner, particularly for thinner liner, given the limited frictional force which can be generated. Also, given that the apparatus is suspended from a wireline, running in the liner will prove impossible above a certain threshold length of liner, due to problems at the surface. As a result, the system of U.S. Pat. No. 3,785,193 is unsuitable to line production tubing along its entire length, which may be in the order of several kilometres.
Other methods and system for expanding a liner within a surrounding tubular string are disclosed in International patent application WO 98/21444 and US patent applications US 2006/052936, US2007/095532 and US 2010/247794.
A general problem with the known tubing lining systems and methods is that pockets of fluids may be trapped between the liner and tubing, which may result in detachment of the liner from the inner wall of the tubing and collapse of the liner.
There is a need for an improved method and system to protect tubulars against corrosion and leakage by use of a tubing liner assembly that automatically removes fluid from the residual space between the liner and tubing, thereby inhibiting formation of fluid pockets and/or longitudinal leakage paths between the liner and tubing and reducing the risk of detachment of the liner from the inner surface of the tubing and the associated risk of subsequent collapse of the liner.